Protecting production wells using natural gas injection

ABSTRACT

A method of protecting a first well from stimulation fluid of a second well includes shutting in the first well; starting injection of natural gas into the first well to increase a pressure of the first well; treating the second well using a stimulation fluid after starting natural gas injection; and stopping injection of natural gas.

BACKGROUND OF THE INVENTION Field of the Invention

Embodiments of the invention generally relate to methods and apparatus for protecting a well from stimulation fluid. Particularly, embodiments of the present invention relates to methods and apparatus for injecting natural gas into a well to protect the well against stimulation fluid from a neighboring well.

Description of the Related Art

In wellbore construction and completion operations, a wellbore is formed to access hydrocarbon-bearing formations (e.g., oil and/or natural gas) by the use of drilling. The drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string is removed and a section of casing is lowered into the wellbore. A cementing operation is then conducted to fill the annulus with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.

Additional completion operations are performed to enable production of well fluids. Examples of such completion operations include the installation of production tubing and various packers to define zones in the wellbore. A perforating string may be lowered into the wellbore and fired to create perforations in the surrounding casing and to extend perforations into the surrounding formation.

A fracturing operation can be performed to enhance the productivity of a formation. Typically, stimulation fluid is pumped into the wellbore to fracture the formation so that fluid flow conductivity in the formation is improved to provide enhanced fluid flow into the wellbore.

When a well is undergoing a fracturing operation, the stimulation fluid may flow toward and undesirably enter a nearby well. The stimulation fluid may damage the well's hydrocarbon productivity. In particular, the stimulation fluid can significantly reduce the hydrocarbon production volumes, thereby reducing the well's Estimated Ultimate Recovery (EUR) of oil and natural gas reserves. Also, the producing well may require costly and time consuming wellbore remediation operations to restore both wellbore integrity and production capability.

This problem is exacerbated by more dense drilling operations. For example, multiple wells have been drilled in close proximity to each other to increase the production of a reservoir. One or more of these wells may be an extended reach horizontal well. Multiple wells have also been drilled on a single drill pad to increase production.

There is a need, therefore, for apparatus and methods of protecting a well from a nearby well undergoing fracturing or stimulation operations.

SUMMARY OF THE INVENTION

In one embodiment, a method of protecting a first well from stimulation fluid of a second well includes shutting in the first well; starting injection of natural gas into the first well to increase a pressure of the first well; treating the second well using a stimulation fluid after starting natural gas injection; and stopping injection of natural gas.

In another embodiment, a method of protecting a producing well from stimulation fluid of a treatment well includes injecting natural gas into the producing well to increase a pressure of the producing well and fractures in communication with perforations of the producing well; and fracturing the treatment well after injecting natural gas into the producing well.

In another embodiment, natural gas is injected into a producing well to act as a barrier against damaging pressure or physical communication of fluid resulting from a stimulation operation at a nearby well.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 illustrates a hydrocarbon producing field having multiple wells.

FIG. 2 illustrate an exemplary producing well configured for injection of natural gas.

FIG. 3 illustrates an exemplary pressure graph of a well undergoing a natural gas injection.

FIG. 4 illustrates an exemplary pressure graph of an unprotected well exposed to fluid and pressure communications from a nearby well undergoing a fracturing operation.

FIG. 5 illustrates another exemplary pressure graph of a well undergoing a natural gas injection.

FIG. 6 illustrates an exemplary wellhead configured for injection of natural gas.

DETAILED DESCRIPTION

In one embodiment, methods and apparatus are provided to protect a producing well from potentially damaging fluid and/or pressure communications resulting from a stimulation treatment at a nearby well.

FIG. 1 illustrates a hydrocarbon producing field having treatment well 100 and one or more candidate wells 101, 102, 103. The treatment well 100 may be undergoing a stimulation treatment to enhance hydrocarbon production of the treatment well 100. In one embodiment, the treatment well 100 may be injected with stimulation fluid such as fracturing fluid or acidizing fluid to increase the effective hydrocarbon drainage area as well as permeability of the producing formation 130, thereby increasing the recovery of hydrocarbons from the treatment well 100. Exemplary stimulation fluids may include fluid or gas systems such as but not limited to singular applications of or combinations of water, liquid hydrocarbons, gas, acid, proppant such as sand or solids, chemicals, and additives that are pumped into a treatment well. Stimulation fluids can include a gas medium such as but not limited to nitrogen (N₂), carbon dioxide (CO₂), methane, and combinations thereof. In one example, stimulation fluid is pumped down the well and flows out perforations or sleeve ports to create artificially induced fractures in the producing formation 130. The treatment well 100 may be a horizontal, vertical, or directional well.

The candidate wells 101, 102, 103 may be producing wells that have been completed and producing hydrocarbons. The candidate wells 101, 102, 103 may be located at the same or different distances from the treatment well 100. In some instances, one or more of the candidate wells is located sufficiently near the treatment well 100 such that the stimulation fluid and/or treating pressures from the treatment well 100 may communicate with the candidate wells. For example, the candidate well 101 is located sufficiently close such that stimulation fluid from the treatment well 100 may reach and enter the candidate well 101. While stimulation fluid may be referred to herein, it is contemplated that stimulation fluid communicating with the candidate well 101 may include liquid, gas, solids such as proppant, chemicals and combinations thereof.

In one embodiment, pressurized gas such as natural gas may be injected into the candidate well 101 to act as a pressure barrier to mitigate and/or minimize ingress of the stimulation fluid and/or treating pressures. In one embodiment, pressure barrier is a downhole pressure envelope or volume created within the near wellbore region by the injected natural gas. FIG. 2 illustrates an exemplary candidate well 101 configured for injection of natural gas. As shown, the candidate well 101 includes a wellbore 120, which may be supported by casing, and a production tubing 125 disposed therein. The production tubing 125 extends from the wellhead downhole to the producing zone 130. An open annulus may be formed between the casing and the tubing 125. Optionally, portions of the candidate well 101 may be isolated using, for example, packers. In addition to stimulation fluid, it is contemplated the pressure barrier may protect the candidate well 101 from other types of treating fluids flowing from a nearby treatment well.

The natural gas utilized for injection may be supplied from a variety of sources 135. For example, the natural gas may be taken from a field gas gathering pipeline, another producing well in close proximity to the candidate well, an onsite production facility, or a commercial production facility. In another example, the natural gas may be liquefied natural gas “LNG,” compressed natural gas “CNG,” or natural gas liquids “NGL” from a nearby production facility or a storage vessel. In yet another example, the natural gas may be stored in a pressurized vessel brought to or located at the candidate wellsite. A flow meter, or similar device, may be used to measure the amount of natural gas supplied to the compressor 141. In one embodiment, the natural gas may be injected into a portion of or the entire footage of the wellbore 120 immediately adjacent to the producing formation 130.

In one embodiment, the natural gas may be injected using a compressor, a pump, or other suitable machine having sufficient power to inject natural gas to increase the pressure in the producing formation 130 to establish a pressure barrier for protecting the candidate well 101. In one example, the compressor 141 is either single stage or multiple stages. The compressor 141 may optionally be provided as an injection compressor skid package 140. In addition to the compressor 141, the skid package 140 may include gauges 142 for monitoring the suction pressure and the discharge pressure into the candidate well 101. The skid package 140 may typically include liquid dumps 143 to remove any liquid build up that may occur in the natural gas. The liquid dump 143 may be manually or automatically controlled. In one embodiment, a flow meter 144 may form a part of the skid package 140. Because the natural gas may come from a variety of sources, the compressor 141 is configured to handle a range of suction pressures from these sources. Further, the compressor 141 is configured to generate sufficient discharge pressures to increase the reservoir pressure sufficiently to create a pressure barrier in the candidate well 101. If additional discharge pressure is required, the skid package 140 may be equipped with additional discharge boosters. In one embodiment, the compressor 141 can generate discharge pressures ranging from 80 psi to 4,000 psi. In another embodiment, the compressor 141 can generate a discharge pressure that increases the reservoir pressure to a pressure at or below the treating pressure of the stimulation treatment for the treatment well 100; for example, between 50% and 100% or between 60% and 90% of the stimulation treatment pressure. In another embodiment, the discharge pressure into candidate well 101 is below the treating pressure of the formation around the wellbore of the treatment well; for example, between 15% and 50% of the stimulation treatment pressure. In yet another embodiment, the pressure of the candidate well 101 is increased from 1.5× to 5× the shut-in pressure of the candidate well 101. In one embodiment, the discharge pressure is less than either the fracture gradient of the producing formation 130 or the rated pressure limitation of the existing wellhead assembly and wellbore tubulars within the candidate well 101.

While a compressor is disclosed in FIG. 2, the natural gas may be supplied to the candidate well 101 using any apparatus capable of supplying pressurized natural gas to increase the near wellbore reservoir pressure of the candidate well 101. For example, the natural gas may be stored in a pressurized vessel that is connected to the wellhead 130 via an injection line. When the injection line is opened, the pressurized natural gas may flow through the injection line and enter the candidate well 101 without passing through a compressor. In another example, the wellhead 130 may be connected to a field gathering pipeline. Natural gas may be allowed to flow from the pipeline to the candidate well 101 without passing through a compressor.

In operation, the candidate well 101 may be injected with natural gas to increase the near wellbore reservoir pressure of the candidate well 101 to mitigate and/or minimize ingress of stimulation fluids and/or pressure from a nearby treatment well 100. Initially, prior to performing a stimulation treatment at the treatment well 100, the candidate well 101 is shut-in and is allowed to naturally build up a shut-in pressure. Exemplary shut-in pressures may be between 100 psi and 1,500 psi. The shut-in pressure may be allowed to build for a period of a few days to multiple weeks; for example, 3 days to 12 weeks, or from 1 week to 8 weeks. It must be noted that natural gas may also be injected into nearby candidate wells 102, 103 to similarly create pressure barriers to mitigate or minimize communications such as stimulation fluid and pressure emanating from the treatment well 100.

After the shut-in pressure is allowed to build, natural gas may be injected into the candidate well 101. A compressor 141, or optionally an injection pressure skid package 140, is connected to the candidate well 101. In particular, the discharge line of the compressor 141 is connected to the wellhead 130 to provide a flow path for the injected natural gas. The natural gas source may be connected to the suction side of the compressor 141. For example, a field gathering pipeline 135 may be connected to the compressor 141 to supply the requisite amount of natural gas. The natural gas may optionally be processed before being supplied into the compressor 141. For example, the natural gas may flow through a filter or dewatering apparatus before entering the compressor. After entering the compressor 141, the natural gas may go through multiple stages of compression until the desired discharge pressure is established. Thereafter, the pressurized natural gas is discharged via the discharge line into the candidate well 101.

Pressure in the candidate well 101 may be allowed to build up before starting the stimulation treatment for treatment well 100. Natural gas is injected into the candidate well 101 to increase the near wellbore reservoir pressure of the candidate well 101 thereby establishing a pressure barrier to a pressure above the shut-in pressure. In one embodiment, the pressure in the candidate well 101 is increased to a pressure between 700 psi and 3,500 psi; preferably, built up pressure is between 1,100 psi and 2,300 psi. In one embodiment, the pressure in the candidate well is increased to a built up pressure at which the pressure in the wellbore is observed to have leveled off, or in some instances, reached maximum pressure build up. The length of time required for the injection build up may be between 2 days and 4 weeks; typically, between 4 days and 14 days.

In one embodiment, the stimulation treatment of the treatment well 100 may begin when the pressure in the candidate well 101 has built up to between 800 psi and 2,100 psi; preferably between 1,000 psi and 1,900 psi. The pressure of the candidate well 101 may be monitored using the pressure gauge 142. Optionally, the pressure of the candidate well 101 may be measured using a gauge 132 coupled to the wellhead 130. The stimulation treatment may begin at the toe section of the treatment well 100 and work toward the heel section. The stimulation fluid being pumped into the treatment well may include a fluid and proppant.

The pressure in the candidate well 101 may be maintained during the stimulation treatment of the treatment well 100. For example, the pressure in the candidate well may be maintained within 30%, within 20%, within 10%, or within 5% above or below the built-up pressure. Without wishing to be bound by theory, it is believed that the higher natural gas pressure in the candidate well 101 and the near wellbore environment, e.g., fractures in the producing formation 130, acts a pressure barrier that deters fluid or pressure communications, e.g., the flow of the stimulation fluid, from entering the candidate well 101. In this manner, the pressure barrier provided by the natural gas may mitigate damages to the candidate well 101 as a result of any ingress of stimulation fluid or damaging pressures.

After completion of the stimulation treatment, the injection of natural gas into the candidate well 101 is stopped. The injected natural gas is allowed to remain in the candidate well 101 in a shut in status until the candidate well 101 is restored to a producing status. In another embodiment, the reservoir pressure in the candidate well 101 may be maintained for a period of time after completion of the stimulation treatment to ensure that potential fluid or pressure communications from the treatment well 100 or other treatment wells are minimized or mitigated. In yet another embodiment, the injection of natural gas is stopped before completion of the stimulation treatment. For example, the natural gas injection may be stopped before the completion of the stimulation treatment if any section, such as the heel section, of the treatment well 100 is sufficiently far away from the candidate well 101. In addition, natural gas injection may be stopped before completion of the stimulation treatment if the near wellbore reservoir pressure does not significantly deplete or leak off during shut in period. For example, the near wellbore reservoir pressure in the candidate well retains at least 80% of the reservoir pressure at the start of the stimulation treatment; preferably, at least 90% of the reservoir pressure. In yet another embodiment, the injection of natural gas into the candidate well 101 may be stopped before commencing the stimulation treatment of the treatment well 100.

FIG. 3 illustrates an exemplary pressure graph of a candidate well in which the production is being shut in and undergoing a natural gas injection operation as described herein. At time T1, the candidate well is shut in. In this example, the pressure of the candidate well at the beginning of shut in is approximately 200 psi. Between time T1 and time T2, the pressure builds naturally to 500 psi, at which time natural gas injection commences. It must be noted the start of the natural gas injection may be independent from the magnitude of the shut-in pressure. The discharge pressure increases until it reaches approximately 1,300 psi at time T3. As seen in the graph, the pressure in the candidate well has generally leveled off by time T3. The discharge pressure is generally maintained before and during the stimulation treatment. During the stimulation treatment, ingress of the stimulation fluid and/or stimulation pressures may cause pressure increases in the candidate well. In this example, a pressure increase is seen at time T4, at about 1,600 psi, but eventually will be deemed to not cause significant damage due to the limited duration and magnitude of the pressure increase. The pressure does not increase dramatically as typically seen in unprotected wells. FIG. 4 illustrates an exemplary pressure graph of an unprotected well exposed to fluid and pressure communications from a nearby well undergoing a fracturing operation. As shown, the pressure increase in an unprotected well caused by ingress of stimulation fluid is faster in time and higher in magnitude. The gradual increase shown in FIG. 3 suggests that the pressure arising from the treatment well is buffered by the pressure barrier created by natural gas injection into the candidate well. FIG. 5 illustrates another example of a pressure graph for a candidate well protected by natural gas injection. In this example, the candidate well experiences multiple pressure increases caused by ingress of stimulation fluid or pressure. However, as depicted, the resulting pressure increases are more gradual and smaller in magnitude when compared to the unprotected well of FIG. 4. After the completion of the stimulation treatment, the compressor or injection source may be shut down at time T5.

FIG. 6 illustrates another embodiment of a wellhead 230 configured for natural gas injection. The natural gas may be injected using a compressor 241 having multiple stages. The suction side of the compressor 241 is connected to a field gathering line 235 to receive natural gas. The natural gas may pass through a coalescing filter 262 prior to entering the compressor 241. Separated liquid from the filter 262 or the compressor 241 may be directed to a production separator/storage tanks 263. Natural gas is discharged from the compressor 241 to the wellhead 230 via an injection line 261. A gauge 242, such as a Barton Recorder or other suitable gauges, may be connected to the injection line 261 to monitor the discharge pressure into the wellhead 230. The injection line 261 may have an optional tie-in 271 to the wellhead 230. In another embodiment, a chemical pump and storage complex 265 may be connected to the injection line 261 to supply one or more chemicals to the wellhead 230.

While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow. 

1. A method of protecting a first well from stimulation fluid of a second well, comprising: shutting in the first well; starting injection of natural gas into the first well to increase a pressure of the first well; treating the second well using a stimulation fluid after starting natural gas injection; and stopping injection of natural gas.
 2. The method of claim 1, wherein the pressure of the first well is allowed to build to a pressure between 100 psi and 1,500 psi prior to starting injection.
 3. The method of claim 1, wherein injection of natural gas comprises injecting the natural gas using a compressor.
 4. The method of claim 3, wherein the natural gas in injected through a wellhead of the first well.
 5. The method of claim 3, where the natural gas is supplied from a field gathering pipeline or a producing well.
 6. The method of claim 3, wherein the natural gas is supplied in a form as one of liquefied natural gas, compressed natural gas, and combinations thereof.
 7. The method of claim 1, wherein the pressure in the first well is increased to a built up pressure between 1,000 psi and 1,900 psi.
 8. The method of claim 7, wherein treating the second well begins after the built up pressure of the first well has increased to between 1,000 psi and 1,900 psi.
 9. The method of claim 1, wherein treating the second well begins after the pressure in the first well has reached equilibrium.
 10. The method of claim 1, wherein the pressure in the first well is increased to a built up pressure between 700 psi and 3,500 psi.
 11. The method of claim 9, further comprising maintaining the pressure in the first well within 30% of built up pressure during treatment of the second well.
 12. The method of claim 1, wherein the natural gas is supplied from a pressurized vessel.
 13. The method of claim 12, wherein the vessel is connected directly to the first well.
 14. The method of claim 1, further comprising producing hydrocarbon from the first well prior to shutting in the first well.
 15. The method of claim 14, further comprising restoring hydrocarbon production of the first well after stopping injection of natural gas.
 16. A method of protecting a producing well from stimulation fluid of a treatment well, comprising: injecting natural gas into the producing well to increase a pressure of the producing well and fractures in communication with perforations of the producing well; and fracturing the treatment well after injecting natural gas.
 17. The method of claim 16, further comprising shutting in the producing well prior to injecting natural gas.
 18. The method of claim 16, wherein the pressure of the producing well is allowed to build to a pressure between 100 psi and 1,500 psi prior to starting injection of the natural gas.
 19. The method of claim 16, wherein the pressure in the producing well is increased to a built up pressure between 1,000 psi and 1,900 psi.
 20. The method of claim 16, wherein treating the second well begins after the pressure in the first well has reached equilibrium.
 21. The method of claim 16, further comprising increasing a pressure of the natural gas prior to injecting the natural gas into the producing well.
 22. A method of protecting a producing well from stimulation fluid of a treatment well, comprising: producing hydrocarbon from the producing well; shutting in production of the producing well; injecting natural gas into the producing well after shutting in the producing well, thereby increasing a pressure of the producing well; and fracturing the treatment well after injecting natural gas. 